It is well known that certain stainless steel alloys experience pitting corrosion and will corrode in the presence of halide (e.g. chloride, bromide, etc.) environments. While the rate at which corrosion will occur depends on a number of factors, such as the steel alloy itself, the hydrogen concentration of the solution often measured as the negative logarithm of the hydrogen ion activity known as pH, the temperature of the environment, the length of contact, etc., some sort of corrosion invariably occurs. Pitting corrosion is especially severe and can cause failure of the equipment. Alloy technology has provided materials to withstand the incidental contact of steel with many different solutions, but the corrosion problem is particularly aggravated when there is no choice but to contact steel with halide-containing material or fluids, as in the case of chemical processing where substances containing halides are employed. In some instances attention has turned toward providing corrosion inhibitors in the medium itself to prevent corrosion of the steel surfaces that it must come into contact with, yet still deliver the acid to its ultimate destination.
Specific environments in which an improved corrosion inhibitor would be appreciated include industrial cleaning and hydrocarbon recovery operations. With respect to oil and gas production, it is well known that during the production life of an oil or gas well, the production zone within the well may be chemically treated or otherwise stimulated to enhance the economical production lifetime of the well.
The vast majority of production and workover conduits comprise carbon steels. These steels were utilized either temporarily or permanently in the well, and treatment and/or stimulation fluids were introduced through them into the well. Sometimes primarily in the drilling and completion of many subterranean wells through formations which contain high concentrations of corrosive fluids such as hydrogen sulfide, carbon dioxide, brine, and combinations of these constituents, the production and workover conduits for use in the wells are now made of high alloy steels. The high alloy steels include, but are not necessarily limited to, chrome steels, duplex steels, stainless steels, martensitic alloy steels, ferritic alloy steels, austenitic stainless steels, precipitation-hardened stainless steels, high nickel content steels, and the like. Often, treatment chemicals are introduced into wells and pipelines in umbilicals that are made of high alloy steels. The high alloy steels include, but are not necessarily limited to, chrome steels, duplex steels, stainless steels, martensitic alloy steels, ferritic alloy steels, austenitic stainless steels, precipitation-hardened stainless steels, high nickel content steels, and the like.
Various corrosion inhibitors are known, to which are added other components, such as intensifiers, surfactants, oil wetting components, and the like. U.S. Pat. No. 2,758,970 describes derivatives of rosin amines, which are represented by the formula:
where R is a radical selected from the group consisting of abietyl, hydroabietyl, and dehydroabietyl, Y is the group CH2R1, X is a radical selected from the group consisting of hydrogen and CH2R1, and R1 represents alpha ketonyl groups. These rosin amines are noted as useful in reducing the rate of corrosion of metals such as magnesium, aluminum and zinc when they are exposed to the action of a corrosive material such as hydrochloric acid.
Further, U.S. Pat. No. 3,077,454 describes compositions for inhibiting corrosion made by combining certain active hydrogen containing compounds with organic ketones having at least one hydrogen atom on the carbon atom alpha to the carbonyl group and an aldehyde selected from the group consisting of aliphatic aldehydes containing from 1 to 16 carbons, and aromatic aldehydes of the benzene series, having no functional groups other than aldehyde groups, and a fatty acid.
Additionally, Mannich base and thiourea inhibitor compositions and methods of inhibiting the acid attack by aqueous hydrofluoric acid on ferrous metal surfaces, and in particular highly reactive ferrous metal surfaces, are described in U.S. Pat. Nos. 3,992,313 and 4,104,303.
It is also known in the corrosion inhibition art to provide various corrosion inhibition aids (sometimes called corrosion inhibitor intensifiers or simply intensifiers) which are used together with the above and other known corrosion inhibitors. For instance, U.S. Pat. No. 4,871,024 to Cizek (Baker Hughes Incorporated) describes copper metal salt intensifiers and U.S. Pat. No. 4,997,040 to Cizek (Baker Hughes Incorporated) relates to certain acid soluble mercury metal salt intensifiers.
U.S. Pat. No. 3,773,465 concerns an inhibited treating acid for use in contact with ferrous surfaces at temperatures of from about 150° F. to about 450° F. (about 66 to about 232° C.) which contains cuprous iodide (CuI; copper (I) iodide) in a concentration of from about 25 to about 25,000 ppm by weight of the acid. The patent notes that it was discovered that the cuprous iodide produced in situ by reactants which also form free iodine will operate in the inventive manner therein, but show a smaller degree of improvement as compared with combining preformed cuprous iodide with an acid. Thus, the patent teaches that the most preferred reactants for producing cuprous iodide in situ are those which do not produce free iodine.
Gas hydrate inhibitors may sometimes contain acids which may cause pitting corrosion when they come into contact with stainless steel. A number of hydrocarbons, especially lower-boiling light hydrocarbons, in subterranean formation fluids or natural gas are known to form hydrates in conjunction with the water present in the system under a variety of conditions—particularly at the combination of lower temperature and higher pressure. The hydrates usually exist in solid forms that are essentially insoluble in the fluid itself. As a result, any solids in a formation or natural gas fluid are at least a nuisance for production, handling and transport of these fluids. It is further not uncommon for hydrate solids (or crystals) to cause plugging and/or blockage of pipelines or transfer lines or other conduits, valves and/or safety devices and/or other equipment, resulting in shutdown, loss of production and risk of explosion or unintended release of hydrocarbons into the environment either on-land or off-shore. Accordingly, hydrocarbon hydrates—particularly preventing or inhibiting their occurrence and growth—have been of substantial interest as well as concern to many industries, particularly the petroleum and natural gas industries.
Hydrocarbon hydrates are clathrates, and are also referred to as inclusion compounds. Clathrates are cage structures formed between a host molecule and a guest molecule. A hydrocarbon hydrate generally is composed of crystals formed by water host molecules surrounding the hydrocarbon guest molecules. The smaller or lower-boiling hydrocarbon molecules, particularly C1 (methane) to C4 hydrocarbons and their mixtures, are more problematic because it is believed that their hydrate or clathrate crystals are easier to form. For instance, it is possible for ethane to form hydrates at as high as 4° C. at a pressure of about 1 MPa. If the pressure is about 3 MPa, ethane hydrates can form at as high a temperature as 14° C. Even certain non-hydrocarbons such as carbon dioxide, nitrogen and hydrogen sulfide are known to form hydrates under certain conditions.
There are two broad techniques to overcome or control the hydrocarbon hydrate problems, namely thermodynamic and kinetic. For the thermodynamic approach, there are a number of reported or attempted methods, including water removal, increasing temperature, decreasing pressure, addition of “antifreeze” to the fluid and/or a combination of these. One type of “antifreeze” is methanol. The kinetic approach generally attempts (a) to prevent the smaller hydrocarbon hydrate crystals from agglomerating into larger ones (known in the industry as an anti-agglomerate and abbreviated AA) and/or (b) to inhibit and/or retard initial hydrocarbon hydrate crystal nucleation; and/or crystal growth (known in the industry as a kinetic hydrate inhibitor and abbreviated KHI). Thermodynamic and kinetic hydrate control methods may be used in conjunction.
Quaternary amine chemistry has been proven to be effective for many applications, including, but not necessarily limited to disinfectants, surfactants, fabric softeners, antistatic agents, corrosion inhibitors for carbon dioxide and hydrogen sulfide corrosion of mild steel, as AA for hydrate control, and the like. However, water quality and fluids separation issues upon the application of quaternary amines are industrial-wide technical challenges, therefore thwarting their broad field implementation to replace conventional thermodynamic hydrate inhibitor (THI) methods. Derivatives from quaternary amine technology that itself possesses potentially severe corrosive tendency, such as betaine, also present similar challenges, irrespective of higher raw material cost (RMC) and complex synthesis routes.
It would be advantageous if corrosion inhibitor compositions were discovered that would be an improvement over the presently known systems containing organic halides. For example, it would be desirable if a methanolic solution which contained an organic halide also contained a corrosion inhibitor that would reduce corrosion, particularly pitting corrosion of the stainless steel that it contacted. There also remains a need for new corrosion inhibitor compositions and methods of use therefore which would work in other acid environments for a wide variety of metals, particularly iron alloys such as steels.